The present invention generally relates to methods for fluid monitoring, and, more specifically, to methods for monitoring the disposition of a fluid in a subterranean formation.
When conducting operations within a subterranean formation, it can oftentimes be desirable to know with some precision the constituent concentrations and/or characteristics of a fluid present in, being introduced to, or being produced from the formation. As used herein, the term “constituent” will be used to refer to a substance present within a fluid. As used herein, the term “characteristic” will be used to refer to the value of a chemical property or a physical property, which also may include an optical property or a mechanical property. Classically, it has been conventional to sample fluids encountered in the course of conducting subterranean operations and analyze them using off-line laboratory analyses, including spectroscopic and/or wet chemical methods. Although such retrospective analyses can be satisfactory in many instances, they are usually not sufficiently rapid to allow real-time or near real-time process control to take place.
Once removed from a subterranean environment, many fluids may exhibit different properties than they do downhole. Although fluids can be sampled from a subterranean environment and brought to the surface for analysis, there is generally no way to conclusively determine if the fluid has been changed in some manner during transit. In addition, highly specialized sampling techniques can often be needed, potentially adding to process complexity and costs. As an added difficulty, downhole fluid analysis techniques can oftentimes be difficult to perform and interpret. Many conventional spectroscopic instruments lack the ruggedness needed for deployment in the harsh conditions of a subterranean environment. More rugged techniques suitable for being carried out downhole may not be sufficiently rapid to allow real-time or near real-time process control to take place.
In addition to analyzing a fluid while it is downhole, it can oftentimes be desirable to know the downhole disposition of a fluid following its introduction to a subterranean formation. For example, it can be desirable to understand the zonal placement of a fluid in the subterranean formation, but many methods for determining downhole fluid disposition can be difficult to carry out and interpret. One technique that has been commonly used to determine fluid disposition within subterranean formations is distributed temperature sensing (DTS), which monitors the thermal front of an injected fluid in comparison to the formation temperature. Thief zones, cross-flow across producing zones, geothermal gradients, formation water, and other factors can complicate a DTS fluid disposition analysis. In addition, DTS analyses can take several hours to acquire and interpret, again precluding real-time or near real-time process control.
Placement of a fluid in an intended region of a subterranean formation can be particularly problematic when there are multiple subterranean zones within the formation, each zone likely having a different effective fluid permeability. One way in which the problem of differential permeability can be addressed is though fluid diversion operations, which may involve physical diversion (e.g., packers) or chemical diversion. Chemical diverting agents (e.g., relative permeability modifiers, sealant compositions, and the like) may form a fluid barrier within the subterranean formation that at least partially redirects the fluid flow to a different subterranean zone, often a zone with a lower effective fluid permeability. Without employing fluid diversion techniques, a fluid may naturally flow to the subterranean zone having the highest effective fluid permeability. This can lead to over-stimulation of some subterranean zones while leaving other subterranean zones under-stimulated. For example, in a wellbore having a substantially horizontal section, the heel of the wellbore may be over-stimulated by a fluid being introduced thereto, while the toe of the wellbore receives insufficient fluid and is under-stimulated. In even more extreme cases, a fluid may enter a subterranean zone where its presence can be unwanted and detrimental, resulting in reduced production and/or formation damage. Thus, improper fluid placement in a subterranean formation can have significant economic ramifications due to waste of material goods, loss of production time, and time and expense of potential remediation operations.
Although fluid diversion techniques can oftentimes be used successfully in subterranean operations to direct a fluid to a desired subterranean zone, the previously mentioned issues regarding determination of the ultimate fluid disposition in the subterranean formation may still remain. Namely, it may still be difficult to rapidly determine if a fluid diversion operation has resulted in the intended redirection of another fluid. Likewise, there is no way to rapidly determine if a diverting fluid itself has been placed in the correct location within a subterranean formation to properly redirect another fluid to a different location. In addition to proper placement of a diverting fluid, chemical compatibility of the diverting fluid with the subterranean formation or a fluid therein can impact the ultimate success of a fluid diversion operation.
Injection operations are another subterranean operation in which it can be highly desirable to know the subterranean disposition of a fluid. In injection operations, an injection fluid, often containing a dye or like tracer, is introduced into a wellbore that is fluidly connected to one or more neighboring wellbores. The fluid pressure in the injection wellbore may be used to drive the production of another fluid from the neighboring wellbore(s). Besides merely observing increased production from the neighboring wellbore(s), the success of an injection operation can also be evaluated by analyzing the neighboring wellbore(s) for the injection fluid (e.g., by analyzing for migration of the tracer from the injection wellbore to the neighboring wellbore(s)).
In addition to evaluating the disposition of a fluid within a subterranean formation, it can also be desirable to know if the fluid is producing a desired effect therein. Evidence of a fluid producing a desired effect may include, for example, the creation or lack of creation of a substance in the presence or absence of the fluid. By way of non-limiting example, in an acidizing operation, the formation matrix may react with an acid to produce soluble species that may not otherwise be present in abundance. It should be noted that even if a fluid is disposed as intended in a subterranean formation, the intended effect of introducing the fluid is not necessarily guaranteed to be achieved. For example, the flow rate of the fluid past the formation matrix may be too fast or too slow for the fluid to have its intended effect, or the fluid itself may sometimes be insufficient in some manner. In even more extreme instances, a fluid may interact with a component of the formation matrix in an unwanted manner to produce damage in the subterranean formation.
Carbonate formations are one type of subterranean formation in which it can be highly desirable to know the disposition and effect of a fluid present therein, particularly an acidizing fluid. When acidizing a carbonate formation, it may be desirable to create wormholes in a treated subterranean zone in order to increase the formation's permeability. In some instances, even if an acidizing fluid is directed to an intended zone of a carbonate formation, wormhole creation may not occur. For example, if the acidizing fluid is not introduced to the formation at the proper rate, simple erosion of the surface of the subterranean formation may occur, rather than the desired wormhole creation needed for effective stimulation to take place. Monitoring only the fluid disposition in this case may be insufficient to determine the success or failure of the acidizing operation.